Flow control means in underwater well system



Dec. 2, 1969 P. s. SIZER ETAL 3,481,395

FLOW CONTROL MEANS IN UNDERWATER WELL SYSTEM Filed Feb. 12, 1968 5 Sheets-Sheet 1 E41 WH- a} -72 s I i .1 v 32 Fae.2 r v INVENTOR FRANK H. TAYLOR PHILLIP S. SIZER ATTORNEY! Dec. 2, 1969 P.'S.S1ZER ETAL- v FLOW CONTROL MEANS IN UNDERWATER WELL SYSTEM Filed Feb. 12, 1968 5 Sheets-Sheet 2 8 R Y R mo m NL R EYE O M w .s A mm L mu RH y FD: y w mm W Y B mn m H m m w f Ff If 3 I 5 J l mu E F Dec. 2, 1969 P.S. SIZER ETAL I FLOW CONTROL MEANS IN UNDERWATER WELL SYSTEM INVENTOR FRANK H. TAYLOR PHILLIP S. SIZER Dec. 2, 1969 P. s. SIZER ETAL FLOW CONTROL MEANS- IN UNDERWATER WELL SYSTEM Filed Feb. 12, 1968 ,5 Sheets-Sheet 4 FRANK H. TAYLOR PHILLIP S- SIZER Dec. 2, 1969 P. s. SIZER ETAL 3,481,395

FLOW CONTROL MEANS IN UNDERWATER WELL SYSTEM Filed Feb. 12, 1968 .5 Sheets-Sheet s INVENTOR FRANK H. TAYLOR PHILLIP S- SIZ ER BY and 7 WQW ATTORNEYS United States Patent 3,481,395 FLOW CONTROL MEANS IN UNDERWATER WELL SYSTEM Phillip S. Sizer, Dallas, and Frank H. Taylor, Carrollton, Tex., assignors to Otis Engineering Corporation, Dallas, Tex., a corporation of Delaware Filed Feb. 12, 1968, Ser. No. 704,855 Int. Cl. E211) 33/035, 43/00 US. Cl. 166-.5 12 Claims ABSTRACT OF THE DISCLOSURE A well installation, particularly for water-covered areas, including a casing hanger supported substantially at the mudline on a string of casing extending into the bed of the body of water, a hanger nipple supported in the casing hanger substantially at the mudline, a flow conductor extending downwardly from the hanger nipple into the bed of the body of water, another flow conductor extending upwardly from the hanger nipple to the surface, an outer pipe extending from the casing hanger at the mudline to the surface surrounding said flow conductors, a well head at the surface between the outer pipe and the conductor s, a flow passage through the hanger nipple communicating the flow conductors connected into the upper and lower ends of the hanger nipple, and safety valves supported in the flow passages of the hanger nipple for shutting in the well for servicing the well installation above the mudline.

This invention related to well installations and more particularly relates to well installation for use at water covered locations.

It is a particularly important object of this invention to provide a new and improved well system especially adapted for use at water coveredlocations.

It is a further object of the invention to provide a well system of the character described which reduces or simplifies the equipment supported at the water surface and connected with the well.

It isa further object of the invention to provide a well system of the character described including valve means located substantially at the mudline so that the damage to or destruction of portions of the system above the mudline does not result in loss of the well since the valve means closes to prevent loss of fluids from the well.

It is still a further object of the invention to provide an off-shore well which may be r e-entered or reestablished subsequent to damage to the well equipment or structure between the ocean floor and the surface of the water It is another object of the invention to provide a well system of thecharacter described which is automatically shut-in in the event of danger'to or failureof surface equipment. y

It is still a further object of the invention to provide a well system as described including circulation paths or flow courses which simplify well completion.

It is another object of the invention to provide a well system of the character described which includes flow passages for effecting secondary recovery production by such means as gas lift.

It is another object 'of the invention to provide a well system of the character described which provides for communication with the casing annulus of each production string of the well for monitoring such annulus to detect leaks before the danger of a blow-out occurs.

It is a further object of the invention to provide an offshore type well system which minimizes the number of- Patented Dec. 2, 1969 "ice off-shore type well system in which a safety valve at the mudline functions as a master valve.

It is another object of the invention to provide a well system of the character described in which any one of the producing strings of the system may function independently of other producing strings of the system.

It is a further object of the invention to provide a well system of the character described which is readily adaptable to remote control methods and apparatus.

It is a further object of the invention to provide a well system including equipment such as safety valves in positions substantially at the mudline and serviceable by remote means through casing extending to the surface thereby minimizing the expense, time and other problems in deep sea diving operations.

Additional objects and advantages of the invention will be readily apparent from the reading of the following description of a device constructed in accordance with the invention, and reference to the accompanying drawings thereof, wherein:

FIGURE 1 is a schematic view partly in section and partly in elevation of a well system embodying the invention adapted to a single production string;

FIGURE 2 is a schematic view similar to FIGURE 1, showing a well system including dual production strings and a single flow passage for the safety valve control fluid;

FIGURE 3 is a schematic view similar to FIGURE 2, showing a modified arrangement for the lift gas flow passages and separate control fluid passages for each safety valve;

FIGURE 4 is a schematic view similar to FIGURES 2 and 3, showing a further modified form of the well system including a different arrangement of the various flow passages communicating with the well;

FIGURES 5A-5D taken together constitute a longitudinal detailed sectional view of the well system shown in FIGURE 3, as seen along the line 55 of FIGURE 7;

FIGURE 6 is a fragmentary view in perspective of the upper end of the hanger nipple of the well system of FIGURE 3 illustrating guiding surfaces which facilitate the insertion of tubing strings and other apparatus into the vertical bores of the nipple; and

FIGURE 7 is a view in section along the line 77 of FIGURE 5C.

Referring to FIGURE 1, a well system 20 embodying the invention is located in a 'body of water 21 having a surface 22 and a floor having a mudline or surface 23. The well system includes a mudline suspension hanger or casinghead housing 24 on a string of casing 25 extending into the floor. The hanger 24 may comprise one of a plurality of concentrically disposed casinghead housings connected on the upper ends of concentrically disposed strings of casing extending to graduated depths in the bottom in a conventional manner. The housings are nested together substantially at the mudline in a standard arrangement substantially as illustrated in a booklet or brochure entitled Cameron Marine System 1966, published by Cameron Iron Works, Incorporated, Houston, Tex., beginning at page 36 within a sub-section of the booklet relating to mudline suspension systems. A similar arrangement is also illustrated at page 1246, vol. 1, Composite Catalog of Oil Field Equipment & Services, 196667 Edition, published by World Oil, Houston, Tex. The number of casings and casinghead housings or hangers employed vary depending upon the characteristics of the well and the earth structure into which it is drilled in accordance with standard procedures.

The mudline suspension system preferably extends at its upper end above the mudline sufficiently to minimize collection of mud and other debris within its various hangers and to facilitate assembly of the system including insertion of the several concentric hangers within each other as the well is drilled and casing is run and set. The hanger 24 is provided with an internal annular downwardly convergent shoulder surface 30 which functions in the mudline suspension system to provide vertical support for the next consecutive component of the system within the hanger which may be a hanger or a hanger nipple as explained hereinafter. In a suspension system including a plurality of hangers similar to the hanger 24, each hanger supports the next consecutive hanger concentrically positioned within it on its annular load bearing shoulder surface 30. The casing connected with each of the hangers of the mudline suspension system extends down to a predetermined distance into the earths structure, each inner casing extending to a greater depth than the casing surrounding it since the outermost casing and hanger is set first. The first casing set, sometimes referred to as the surface casing, may, for example, extend downwardly from the mudline 500 to 600 feet and may be as large as 30 to 50 inches in diameter.

A casing hanger 31 is supported Within the hanger 24 secured on a lower string of casing 32 connected at its upper end into the lower end portion of the hanger. An upper string of casing or conductor pipe 32a is secured to and extends from the hanger 31 to a well head 33 secured to the casing near the water surface. The casing hanger 31 has an external annular downwardly convergent shoulder surface 31a which seats on the internal shoulder 30 of the hanger 24 providing a vertical support for the hanger 31. A hanger nipple 34 is disposed within the hanger 31 supported on a downwardly convergent internal annular shoulder surface 35 provided in the hanger which engages an external annular downwardly convergent shoulder surface on the hanger nipple As explained in greater detail hereafter the hanger nipple 34 is inserted into the hanger 31 by remotely located equipment positioned at the surface of the water. The hanger nipple 34 has a vertical bore 41 for fluid flow in servicing and producing the well. In accordance with the invention, a safety valve 42 is releasably locked in the bore 41 for shutting off flow of production fluids substantially at the mudline in case of failure of or damage to the well system equipment above the mudline suspension system and when certain servicing procedures are carried out in the well.

A suitable safety valve which may be inserted and removed with wireline apparatus and is remotely controlled by fluid pressure is an Otis Wire Line Removable Ball Type Safety Valve described and illustrated at page 3841 of the Composite Catalog of Oil Field Equipment and Service, 196667 Edition, published 'by World Oil, Houston, Tex.

A string of lower casing 43 is supported from the hanger nipple 35 extending downwardly into the floor within the casing 32 to a depth below the casing 32 passing through a formation to be produced within the casing, not shown. Concentrically disposed within and removably supported from the hanger nipple is a string of production tubing 44 which communicates at its upper end with the vertical bore 41 of the hanger nipple and is open at the lower end, not shown, into the casing 43 for admitting well fluids to the tubing. The casing strings 32 and 43 define a casing annulus 45 below the hanger nipple which communicates at its upper end with vertical flow passages 50 extending along the hanger nipple within the hanger 31 communicating with a casing annulus 45a above the hanger nipple leading to the well head 33. The spacing between the production tubing 44 and the casing 43 defines another casing annulus 51 which communicates at its upper end with a vertical flow passage 52 extending through the hanger nipple 34 to provide, for example, for such well functions as secondary recovery of well fluids by means such as lift gas procedures.

An upper casing string 43a connects between the hanger nipple 31 and the wellhead 33. A string of production tubing 44a is supported through the wellhead and removably connected at its lower end into the hanger nipple 34 communicating with the flow passage 41 of the nipple. The casing annulus 45a above the hanger nipple is defined within the casing 32a around the casing 43a. An annulus 51a is defined around the production tubing 44a within the casing 43a communicating at its lower end with the vertical passage 52 through the hanger nipple 34 so that the upper annulus 51a communicates with the lower annulus 51 through the hanger nipple. The upper end of the annulus 45a in the wellhead communicates with a conduit 60 provided with a valve 61 for fluid communication with the annulus 45a for various standard well procedures and particularly for monitoring the annulus pressure for leak detection. Similarly, a conduit 62 is connected into the wellhead communicating with the upper end portion of the annulus 51a for providing such functions as lift gas injection downwardly through the annulus 51a and the passage 52 in the hanger nipple into the annulus 51 below the mudline suspension system.

A tubing string 65 provided with a valve 66 is connected through the wellhead downwardly in the casing 32a into the upper end of the hanger nipple communicating with a vertical flow passage 67 in the hanger nipple connecting with a horizontal flow passage 68 providing fluid communication to the removable safety valve 42 for hydraulic fluid control of the safety valve from a location remote from the mudline suspension system, such as on a platform at the surface or a shore located control station which may be a substantial distance from the well. Such remote safety valve control is standard procedure and generally includes providing fluid pressure to the safety valve from the remote control station for holding the safety valve at an open position. An Otis Surface Control Manifold illustrated and described at page 3845, Composite Catalog of Oil Field Equipment and Services, 1966-67 Edition, may be used to supply the control fluid pressure to the safety valve. A decrease in the control fluid pressure as by destruction of the well equipment extending to the surface or by a reduction of the control fluid pressure from the control station releases the safety valve to be moved to its closed position by a spring and/or the production fluids in the flow passage 41 below the safety valve for shutting the well in. As explained in greater detail hereinafter, the portions of the well system above the mudline suspension system at the mudline 23 may be damaged or destroyed with the resultant shutting-in of the well by the safety valve 42 and the well is reactivated after replacement of the damaged equipment by remote reopening of the safety valve. Leakage of fluids into the outer casing 32 is detected by monitoring the pressure within the conduit 60 at the surface. The well is converted to secondary recovery by use of the conduit 62 for injection of lift gas into the annulus 51a with the gas flowing downwardly in the passage 52 in the hanger nipple to the lower annulus in which it flows to a valve, not shown, for entry into the production tubing 44.

Another well system 70 embodying the invention and adapted to accommodate two production tubing strings is illustrated in FIGURE 2. A casing head housing and hanger unit 71 of a conventional mudline suspension system of the type already explained is supported substantially at the mudline on the casing 72. Another casing hanger 73 is supported within the casing head 71. Sup ported from the hanger 73 is a string of lower casing 74 secured at its upper end into the hanger unit. An upper casing or conductor pipe 74:: extends upwardly through the water to a wellhead 75 at the surface. A hanger nipple 76 is removably supported within the hanger 73, on a shoulder 73a which engages a shoulder 76a on the hanger nipple.

The hanger nipple 76 is provided with a pair of vertical laterally spaced flow passages 77 each of which receives a releasably secured safety valve 78 for controlling fluid flow through each of the flow passages. A pair of laterally spaced lower casings 80 are connected along upper end portions into the lower end of the hanger nipple aligned with the passages 77. A production tubing string 81 in each casing 80 is connected at an upper end into the hanger nipple 76 each communicating with a vertical flow passage 77. The casing 74 defines a casing annulus 82 around the pair of laterally spaced casings 80 below the hanger nipple. The annulus 82 communicates at its upper end with vertically extending flow passage 83 between the hanger 73 and the hanger nipple. Similarly, each pair of the casings 80 and production tubings 81 define an annulus 84 each of which communicates at its upper end with a vertical flow passage 85 extending through the hanger nipple primarily for providing a path for gas lift procedures and other well methods including fluid flow steps.

Laterally spaced upper casing strings 80a are connected between the hanger nipple and the wellhead 75. A productiton tubing string 81a is connected between the well-head and the hanger nipple in each casing 80a. Each tubing string 81a connects into the upper end of passage 77 in the hanger nipple and includes a valve 81b for controlling flow from the wellhead through each tubing string. The upper casing 74a defines an upper annulus 82a around the upper casing strings 80a. The annulus 82a communicates with the upper end of the flow passage 83 around the hanger nipple 76. Each upper casing 80a and enclosed tubing string 81a defines an upper anulus 84a which communicates at its lower end with the upper end of a flow passage 85 through the hanger nipple. A conduit 81 having a valve 92 connected into the wellhead 75 communicates with the upper end of the annulus 82a for such purposes as monitoring the pressure in the casing 74 below the mudline suspension system to determine, for example, if leaks exist in one of the casing strings. Similarly, a pair of conduits 93 are connected into the wellhead 75 each communicating with the upper end of an annulus 84a to provide separate downward injection of lift gas for each production tubing string through the annulus 84 and into each production string 81 through a valve device, not shown, below the hanger nipple.

Well production fluids flow in the well installation upwardly in each tubing 81, through each passage 77 in the hanger inpple 76, and upwardly through the wellhead 75 in each tubing string 81a.

Remote fluid control of the safety valves 78 is provided through a conduit 100 connected through the wellhead 75 into the upper end of a flow passage 101 in the hanger nipple 76. The flow passage 101 connects with horizontal flow passages 102 communicating both of the safety valves with the common control fluid line so that either damage to or destruction of the well equipment above the mudline extension system or a reduction in control fluid pressure from the control station effects simultaneous closing of the safety valves 78.

The safety valves 78 are insertable into and removable from the hanger nipple '76 by conventional procedures .carried out through the casings 80a extending from the surface to the hanger nipple. The well equipment above the mudline suspension system is repairable and replaceable in the event of damage or destruction while the well is held in a shut-in condition by the safety valves with the well subsequently being re-established after repair or servicing by reopening the valves.

Another form of well installation 110 embodying the invention illustrated in FIGURE 3 similar to the system 70 of FIGURE 2 providing, however, for separate control of each of the safety valves and a modified flow pattern for the injection of lift gas. The well system 110 includes a casing hanger 111 supported substantially at the mudline 23 on a string of surface casing 112. A hanger 113 disposed within the hanger 111 is supported on a downwardly convergent shoulder 111a provided in hanger 111 engaging a downwardly convergent shoulder 13a provided on the hanger 113. The casing hanger 113 is connected at its lower end to the lower casing 114 and at its upper end to a string of casing or conductor pipe 114a extending to a wellhead 115 at the surface of the water. A hanger nipple 116 is supported within the hanger 113 on a shoulder surface 113b which engages a shoulder surface 116a on the hanger nipple. The hanger nipple has laterally spaced vertical passages 117 in which are disposed movably locked conventional safety valves 120. A pair of laterally spaced lower casing 121 are connected into the hanger nipple. A string of production tubing 122 is supported from the hanger nipple and within the casings 121 and connected into each of the vertical flow pass-ages 117. The casing 114 defines an annulus 123 aroundthe casings 121 which communicates at its upper end with vertical flow passages 124 provided between the hanger nipple and the hanger 113 communicating with an annulus 123a in the casing 114a above the hanger nipple. Each of the casings 121 defines an annulus 130 around the production tubing string 122 enclosed therein. Each annulus 130 communicates at its upper end with an angular flow passage 131 in the hanger nipple connected with spaced vertical flow passages 132 in the hanger nipqigeo to provide for the flow of lift gas into each annulus A pair of laterally spaced upper casing strings 121a are connected between the wellhead 115 and the hanger nipple each enclosing an upper production tubing 122a connected at its lower end into the upper end of one of the vertical flow passages 117 and extending upwardly through the wellhead and provided with a valve 122b. A conduit 141 having a valve 142 is connected into the wellhead communicating with the annulus 123a. The casings 121a each define an annulus 130a with the enclosed production tubing string 122a which communicates at its upper end with a conduit 143' connected into the well- 'head. The lower end of each annulus 130a communicates with a flow passage 144 in the hanger nipple extending into one of the bores 117 to the safety valve 120 in the bore to supply control fluid pressure from the conduit line 143 for individual control of each of the safety valves from a suitable pressure control station, not shown, connected with the line 143.

A pair of tubing strings 150 having valves 150a are connected through the wellhead 115 into the upper ends of the vertical gas flow passages 132 through the hanger nipple 116 to supply lift gas through the conduits 150 and the hanger nipple into each annulus 130 for the secondary recovery of well fluids through each of the production tubing strings 122.

The well system 110 functions in the same manner as the well system 70, as already explained, with the exception, however, that lift gas and the safety valve control fluid follow different flow passages andthe safety valves are individually controlled. The well installation above the mudline is similarly adapted to be replaced or repaired while the well is shut in by the safety valves located substantially at the mudline so that damages to the system above the mudline effects closing of the safety valves immediately shutting-in the well and preserving the well in a condition for reestablishment of its flow subsequent to repair.

The still further form of well system embodying the invention is illustrated in FIGURE 4, which utilizes a modified upper conduit arrangement between the mudline suspension system and the wellhead while retaining the structure of FIGURE 3 below the hanger nipple. The Well system 170 includes a hanger 171 supported at the mudline on a string of surface casing 172. Another hanger 173 is supported within the hanger 171 and connected at its lower end to the upper end of a string casing 174. An upper casing or conductor pipe 174a extends from the hanger 173 to a wellhead 175 at the surface of the water. A hanger nipple 176 is supported within the hanger 173 substantially at the mudline and is provided with a pair of laterally spaced vertical flow passages 180 each of which receives a remotely controllable removable safety valve 181. The hanger nipple is connected with two strings of casing 182 and production tubing 183 secured into the lower end of the hanger nipple. Each of the production tubing strings communicates with one of the vertical flow passages 180 through the hanger nipple so that the well production in each tubing string is directed through a safety valve in the hanger nipple.

The casing 174 defines an annulus 184 around the pair of casings 182 communicating at its upper end with vertically extending flow passage 185 between the hanger nipple 176 and the hanger 173 for well circulating purposes and to permit the pressure within the annulus 184 below the mudline suspension system to be monitored to detect leaks in the casing strings. Each casing 182 defines an annulus 190 around the production tubing string extending through the casing. Each annulus 190 communicates with the lower end of a vertical flow passage 191 extending through the hanger nipple to conduct lift gas downwardly around each production tubing string to a gas lift valve, not shown, positioned in the tubing string.

A pair of laterally spaced upper production tubing strings 183a are connected through the wellhead 175 downwardly into the upper ends of the flow passages 180 in the hanger nipple. Each production tubing string is concentrically spaced within a tubing string 201 which defines an annulus 202 around this production tubing string which communicates with a conduit 203 connected into the wellhead for conducting safety valve control fluid into a flow passage 204 in the hanger nipple communicating with the safety valve 181 positioned in the flow passage 180 of the hanger nipple. Around each tubing string 201 another casing 205 is connected between the wellhead and the upper end of the hanger nipple defining an annulus 210 which communicates at its upper end with a conduit 211 connected into the wellhead. Each annulus 210 communicates at its lower end with one of the vertical passages 191 in the hanger nipple for conducting lift gas from the surface through the mudline suspension system into the annulus 190 around each of the lower production strings of the well below the hanger nipple. The casing 174a defines an annulus 184a around the pair of casings strings 201 between the mudline suspension system and the wellhead. The upper end of the annulus 184a communicates with a conduit 213 with a valve 214 providing means for monitoring the pressure in the lower annulus 184- which is communicated into the lower end of the annulus 184a through the vertical flow passages 185 to detect leaks in the casings below the hanger nipple.

If desired, the upper concentric conduits comprising K each set of the production tubing strings 183a and the casing 201 may be made up in unitary sections which can be run into the well and pulled from the well thereby reducing the steps required to separately run the casing strings 201 and the production strings 183a. Also such 1 construction may reduce the space required in the wellhead and the upper casing 172a as such a unit may be of less outside diameter than when using separate tubing and casing.

The well system 170 functions in the same manner as the previously described systems providing means for shutting in the well at the mudline in the event of destruction or damage to the well structure above the mudline suspension system where the safety valves are removably located. The well structure is replaceable and repairable above the mudline after which the well is returned to service by remote manipulation of the safety valves.

In summary, the various flow courses followed by the fluids in the well installation in producing the well are briefly as follows. Control fluid for the purpose of controlling the operation of each of the safety valves 131 is communicated into the wellhead in the conduits 203 and downwardly through the annulus 202 into the flow passage 204 of the nipple hanger 176 through which the fluid flows to the safety valve in the vertical flow passage 180 of the hanger nipple. Produced fluids from the well enter the lower production tubing strings 183, flow upwardly through the tubing strings and the vertical flow passages 180 of the hanger nipple and the safety valves therein and upwardly to the wellhead through the upper production strings 183a. In addition to the control of the flow of the produced fluids by the safety valves, the valves 18312 in each of the upper production strings at the water surface may be used to control the flow of fluid in the production strings from the surface equipment. In the case of secondary recovery by gas lift, the lift gas is introduced for each production string through the conduits 211, flows downwardly in the annulus 210 passing through the hanger nipple in the vertical flow passage 191 from which it flows downwardly around the lower production string in the annulus around each string entering the production string through gas lift valve, not shown, included in each string. Any leakage in the annulus 184 within the lower casing 174 flows upwardly along the passage 185 into the upper annulus 184a to the surface equipment where monitoring equipment, not shown, may detect it.

The well system of FIGURE 3 is shown in detail in FIGURES 5A through 5D wherein identical reference numerals denote the same components of the well system illustrated in FIGURE 3. The wellhead is conventional in structure including a flanged exit assembly 115a and a flanged bradenhead 115b coupled at the flanges and adapted to accommodate the production tubing string 122a and the pair of lift gas tubing strings 150 which are aligned with each other as viewed in a horizontal plane along a line extending substantially between and at 90 degrees to the production tubing strings 122a. The tubing strings all extend upwardly through the wellhead to the valves, included in the strings. A suitable pack-off assembly 225 including a seal 230 and O-ring seals 231 is secured with the exit assembly around each of production strings 122a. Similarly, a pack-off assembly 232 including an internal packing 233 is secured in the exit assembly around each of the lift gas tubing strings 150. Each casing string 121a terminates in the lower portion of the exit assembly and a casing pack-off 234 is disposed in the exit assembly around each of the casings. The bradenhead is connected with the upper end of the upper casing section 114a by an internally threaded coupling 240.

The conduits 143 are connected into the exit assembly above the casings 121a for communicating control fluid pressure into each annulus a for control of the safety valve 120. The conduits 141 are connected into the bradenhead for communication with the annulus 123a.

The lower end of the casing string 114a is threaded into a casing connector 241, which is threaded along a lower end portion into the upper end of the hanger 113 which as already explained with reference to FIGURE 3 is supported on its surface 113a in the hanger 111 shown schematically in FIGURE 3 but not illustrated in detail in FIGURE 50. The upper end of the lower casing 114 is threaded into the lower end of the hanger 113 and extends downwardly a predetermined distance into the bottom or floor structure 23.

Each upper string of casing 121a is threaded along a lower end portion into the upper end of the hanger nipple 116 each communicating with one of the vertical flow passages 117 in the hanger nipple. The hanger nipple 116 is supported in the hanger 113 within a collet 250 and which is externally threaded along an upper end portion 251 into the threaded bore portion 113!) of the hanger 113 and is provided with a plurality of downwardly extending circumferentially spaced collet fingers 252 which engage the downwardly and inwardly convergent shoulder surface 1131) of the hanger 113. The upper portion of the collet 250 has an internal diameter slightly larger than the diameter of the hanger nipple 116 to provide an annular space 252 along the hanger nipple within the collet so that there is fluid communication between the upper annulus 123a within the upper casing 114a through the casing connector 241 into and through the upper threaded portion of the hanger 113 into the upper end portion of the collet downwardly into the space around the collet fingers around the hanger nipple within the hanger 113. The bore portion 113a of the hanger 113 is larger than the hanger nipple 116 below the collet fingers 252 providingcommunication downwardly into the lower casing annulus 123 within the casing 114 below the hanger nipple. The hanger nipple 116 has a downwardly tapered serrated surface 253 which engages the collet fingers 252 supporting the hanger nipple against downward movement in the hanger 113. Thus, there is a communication from the lower casing annulus 123 upwardly through the mudline suspension system around the hanger nipple 116 around the collet fingers'252 and within the upper portion of the collet through the upper portions of the hanger 113 and casing connector 241 into the upper casing string 114a and to the surface at the wellhead where the casing annulus 123a communicates with the conduits 141. The pressure in the conduits 141 may thus be monitored to detect leaks in the well in the lower casings 114 and 121 below the mudline.

Each String of upper production tubing 122a is secured at its lower end into a production tubing anchor 260 threaded into the upper end portion of the hanger nipple in the bore 117 into which the tubing communicates. Along the lower end portion of each production tubing anchor is an external seal 261 which seals around the tubing anchor with the internal wall surface of the bore 117 to prevent communication between the interior of the production tubing and the casing annulus around it above the tubing anchor. The upper end portion of each tubing anchor 260 is slightly smaller in diameter than the casing 121a encompassing it to provide fluid communication from each annulus 130a into a connecting flow passage 144 in the hanger nipple for control fluid communication from the annulus 130a to the ball valve 120 disposed in each connecting bore 117. The lower end of each control fluid passage 144 in the hanger nipple 116 communicates with the bore 117 between upper and lower seals 120a and 120b on the safety valve in the flow passage to conduct the control fluid pressure to the safety valve;

Each of the safety valves 120 is releasably locked by locking dogs 120a which engage an internal locking recess 113d around the bore 117 receiving the safety valve. As explained hereinafter, the safety valve is insertable and removable when the production tubing 122a and its tubing anchor 260 are removed from above the valve in the casing 121a and the hanger nipple. The reduced lower end portion 120d of each safety valve provided with seals 120e is inserted into a tubing hanger 270 supporting a lower production tubing string 122 from the nipple 117. Each tubing hanger 270 has a tapered lower end portion which is supported on a downwardly convergent surface 117a in the bore 117 in which the hanger is disposed. The reduced lower end portion 120d of the safety valve is not threaded so that it is insertable and removable from the tubing hanger by a longitudinal movement only.

.Each lift gas tubing string 150 is connected at its lower end into a tubing anchor FIGURE B, 280, which is threaded into an upper end portion of the hanger nipple communicating with a vertical flow passage 132 of the hanger nipple. Each flow passage 132 communicates through a passage 132a into the lower annulus 130 below this hanger nipple. The orientation of the FIGURES 5A-5D preclude showing both of the gas lift tubing strings and associated fiow passages though it is to be understood that the other gas lift tubing string communicates with the other lower casing annulus 130 in the same manner.

Each lower tubing string is supported from the hanger nipple 116 by the tubing hanger 270 as already explained. Each lower production tubing 122 is connected by a coupling 290 secured with a landing nipple 291 threaded into the lower end of the tubing hanger 270. The landing nipple serves to support a plug or other suitable well device inserted through the safety valve above the nipple to plug the production tubing at times when removable of the safety valve is desired. The tubing hanger arrangement illustrated permits ready installation and removal of each lower production tubing when the safety valve 120 is not present in the mudline suspension system above the tubing string.

'Each string of casing 121 below the mudline suspension system extends downwardly to a producing formation cemented in a conventional manner. Each lower production tubing 122 inclueds a suitable and conventional sleeve valve device 300 which may be used to admit lift gas from the annulus 130 into the tubing string and a Suitable conventional packer 301 for packing-off the annulus around the production tubing string. A lower end portion 122a of each production tubing string is connected below the packer and open at its lower end to permit production fluid within the casing around the tubing string to flow into the tubing string. The tubing string obviously may be equipped with other production tools in any suitable manner depending upon the welll conditions and the particular production practices involved.

In the procedure of installing the well system the mudline suspension system including the hanger unit 111 with its associated casing are run and set at the mudline in a suitable conventional manner. The lower casing 114 connected 'with the lower end of hanger 113 and the upper casing string 114a connected with the upper end of the hanger 113 are run and set through the hanger 111 in a conventional manner with the hanger 113 being supported by the hanger 111 and the upper casing string 114a extending to the surface of the Water in which the well is located. As already explained the hangers 111 and 113 are located substantially at the mudline 23, while the upper end of the upper casing string 114a is at the platform in the water from which the well is being drilled. The bradenhead 115b of the wellhead is connected on the upper end of the upper casing string with suitable blow-out preventers made up on the bradenhead.

The lower dual casing strings 121 are run to the desired depth through the lower casing string 114. The hanger nipple 116 is made up on the lower casing strings with suitable check valves installed in the landing nipple portions 132b of the gas lift valve injection flow passages 132 in the hanger nipple. A suitable wire line removable cementing sleeve is installed in each of the safety valve flow passages 117 of the hanger nipple. The upper strings of casing 121a are connected to the upper end of the hanger nipple which is then run and landed in the casing hanger 113 of the mudline suspension system at the mudline 23. Both of the lower casing strings 121 are then cemented in a conventional manner with cement returns flowing back to the surface through the lower annulus 123 and the upper annulus 123a of the casing strings 114 and 114a, respectively. The cementing sleeves are then removed by suitable standard wire line procedures from each of the bores 117 of the hanger nipple. The lower production strings 122 including suitable packers 301 and sleeve valve units 300 and landing nipples 291 each connected on a tubing hanger 270 are run to the desired depth and supported from the tubing hanger within the hanger nipple 116. As already explained, each of these lower production tubing strings is supported from a hanger 270 which rests on the shoulder 117a at the lower end of the vertical flow passage 117 in the hanger nipple. The lower production tubing strings are run in on the handling strings which are connected into the hangers 270 and packed-off at the wellhead for testing the packers, perforating, and circulating and bringing in the well by suitable conventional procedures, if desired.

Standard plug chokes are set in the landing nipple 291 of each of the production strings below its tubing hanger 270. The handling strings are then removed and a safety valve 120 run in on a wireline and set in each of the vertical passages 117 of the hanger nipple. The upper production tubing strings 12211 are then each run into their upper casing 121a until the tubing anchor 260 at the lower end of each of the production strings is engaged with the hanger nipple, as illustrated. The gas lift tubing strings 150 are then run into the well and connected by means of tubing anchors 280 to the hanger nipple. The wellhead surface equipment is then connected.

Control fluid pressure is applied through each annulus 130a to the safety valves 120 to open the valves and a wire line is employed to remove the plug choke in the landing nipples 291 of the lower production strings. If desired, check valves from the landing nipples and the gas lift valve flow passages of the hanger nipple may be removed by wire line procedures and the gas lift valve courses used for circulation purposes after opening of the sleeve valves 300 for bringing the well in. In such event, circulation is effected downwardly into the production strings and returned through the normal flow courses used during gas lift which includes the lower casing annulus 123 and the gas lift tubing strings 150.

Among the most important features of the well system 110 and the other systems illustrated and described herein are the reduction in and the simplicity of the surface connections and equipment required, together particularly with the positioning of the safety valves in the nipple and hanger assembly at the mudline so that destruction or damage to the well system above the mudline does not result in loss of the well but may simply effect the closing of the safety valves thereby shutting the well in during replacement or repair of the equipment.

For example, in the Well system 110 the upper production tubing strings 122a and the gas lift tubing strings 150 are readily withdrawn and reintroduced into the well from the surface subsequent to a reduction in the control fluid pressure supply to the safety valves responsive either to a loss of such pressure or due to equipment malfunction or damage or to a positive reduction of the pressure by means of the surface manifold system employed, and the resultant closure of the safety valves. If replacement of a safety valve is desired wire line equipment is employed to set a plug choke in the landing nipples 291 below the valve to shut off upward flow from the lower production string. The upper production strings 122a are then removed followed by the removal of the safety valves with the well being held at a shut-in condition by the plugs in position below the safety valves in the lower production strings. The safety valves then may be replaced followed by the replacement of the upper production strings followed by removal of the plugs below the valves and the reactivation of the valves by control from the control fluid pressure system at the surface.

In the event of a total destruction of the well system above the mudline, the resultant loss of control fluid pressure to the safety valves permits the valves to close thereby shutting in and protecting the well While the equipment extending to the surface is replaced. In the event of such destruction, the services of a diver are employed to assist in the clearing of the damaged equipment from the top of the mudline suspension system, mainly the removal of such damaged equipment as the casing connector 241 and in the stubs or fragments of the upper production casing strings 121a. Also, of course, any remnants of the production and lift gas tubing strings must also be removed from the upper end of the mudline suspensions system. A diver would then be used to guide in and connect the inner casing string 121a and the outer casing string 114a. The replacement of the upper production tubing strings and lift gas tubing strings may then be accomplished remotely from surface in the same manner as already explained in connection with the installation of the well system. The safety valves may then be reopened by fluid pressure through the control fluid passages to reestablish flow from the well.

The flexibility of the Well system permits application of a number of standard well procedures beginning with the cementing of the casing strings during the drilling of the well including the installation of the equipment of the well system. In cementing the casing string 121 within the string 114, the cement returns may flow upwardly in the annulus 123 between the casing string. The well system may be used to produce the well by gas lift by injection of lift gas into the conduit through which the gas flows downwardly through the safety valve nipple and hanger 114 into the annulus 130 around each of the lower production tubing strings. The gas flows downwardly in each such annulus, entering the production tubing string through the sleeve valve unit 300 in which a gas lift valve has been installed through the tubing string and locked within the sleeve valve unit as illustrated at page 3873 of the Composite Catalog of Oil Field Equipment and Services, 196667 Edition, published by World Oil, Houston, Tex.

The details of the well systems shown in FIGURES l, 2 and 7 are substantially similar to the details of the system of FIGURE 3, varying in such respects as necessary only to provide the different flow courses or paths illustrated schematically in FIGURES l, 2 and 7. The functions, however, of the well systems 20, 70 and are basically the same as those of the well system 110, as explained in detail and the various components of these well systems are replacable and repairable by following the steps already explained.

It will be see that a new and improved well system for completing wells, for producing wells by primary or secondary recovery methods and for killing or shutting in a well has been described and illustrated.

It will be further seen that each of the well systems includes safety valve means located at the mudline so that destruction and damage of the well equipment above the mudline causes the well to be shut in with only a minimum of fluid loss, if any, While the equipment is between the mudline and the surface is repaired or replaced.

What is claimed is:

1. A well installation for a well located in a body of water and having casing therein comprising: a well head connected to the upper end of the casing at the earth level at the bottom of the body of water; conduit hanger and valve support means secured in said well head; flow conduit means supported and extending downwardly from said conduit hanger and valve support means; flow conduit means connected with and extending upwardly from said conduit hanger and valve support means to the surface of the body of water; said conduit hanger and valve support means having flow passage means communicating said downwardly and upwardly extending flow conduit means; and valve means disposed in said flow passage means operable to be closed for shutting off flow communication between said upwardly and downwardly extending flow conduit means; and means for reopening said valve means for re-establishing fluid communication between said upwardly and downwardly extending flow conduit means.

2. A well installation as defined in claim 1 wherein means is provided for operating said valve means controllable from a remote location.

3. A well installation as defined in claim 1 wherein said valve means is removable and replaceable through said upper conduit means from a remote location.

4. A well installation as defined in claim 3 wherein said valve means includes means operable to hold said valve means at an open position responsive to fluid pressure communicated thereto from said remote location and means operable to close said valve means when said pressure is reduced below a pre-determined level.

5. A well installation for an off-shore marine location comprising: conduit suspension means including a lower well casing extending downwardly in said well, a casing head connected to the upper end of said casing; substantially at the mudline of the ocean bed at such location; an upper casing secured at its lower end portion to the upper end portion of said casing head and extending upwardly from said casing head to substantially the surface of the water; a valve support and conduit hanger means removably supported in said casing head substantially at said mudline, said valve support and hanger means being provided with a. vertical flow passage therethrough; lower conduit means secured at its upper end to the lower end of said valve support and conduit hanger means in communication with said flow passage through said means; and upper conduit means connected at its lower end with the upper end of said valve support and hanger means in communication with the upper end of said flow passage through said valve support and hanger means; well head means secured substantially at said water surface to the upper end of said upper casing and to said upper conduit means;. and valve means supported in said flow passage means through said hanger means operable for shutting off flow communication through said flow passage from below said hanger means to provide for servicing said well installation above said hanger means.

6. A well installation as defined in claim wherein said valve means includes operating means controlled from a remote location and adapted to close responsive to a predetermined condition for servicing said well installation above said hanger means and to be reopened from said remote location for re-establishing flow communication between said conduit means below said hanger means and said conduit means above said hanger means.

7. A Well installation as defined in claim 6 which includes means for communicating fluid pressure to said valve operating means through said upper casing for controlling said valve from said remote location.

8. A Well installation as defined in claim 7 wherein said conduit means between said hanger means and said well head means is removably secured and adapted to be remotely inserted into and removed from said hanger means from said well head means.

9. A well installation as defined in claim 8 wherein said valve means is removable from and insertable into said flow passage means of said hanger means through said upper conduit means between said hanger means and said well head means.

10. A well installation as defined in claim 9 wherein said lower conduit means below said hanger means includes a production tubing string removably supported from said hanger means and adapted to be inserted through and removed through said hanger means remotely from said well head at the surface.

11. A well installation as defined in claim 10 wherein said hanger means includes flow passage means communicating with said valve means for controlling said valve means between open and closed positions and including conduit means between said Well head and said hanger means for communicating said valve means with control fluid pressure from said remote location.

12. A well installation as defined in claim 11 wherein said conduit means above and below said hanger means includes flow passage means for conducting lift gas from said well head to said hanger means and said hanger means includes flow passage means for communicating said lift gas to said conduit means below said hanger means for conducting said lift gas to said conduit means below said hanger means for producing said well with said lift gas.

References Cited UNITED STATES PATENTS 3,252,476 5/1966 Page 166224 X 3,280,914 10/1966 Sizer et a1 166-224 X 3,363,693 1/1968 Bohlmann 166224 X JAMES A. LEPPINK, Primary Examiner U.S. Cl. X.R. 166224 

